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C O R P O R AT E P R O F I L E
J u n e 2 0 1 7
In the interests of providing Keyera Corp. (“Keyera” or the “Company”) shareholders and potential investors with information regarding
Keyera, including Management’s assessment of future plans and operations relating to the Company, this document contains certain
statements and information that are forward-looking statements or information within the meaning of applicable securities legislation, and
which are collectively referred to herein as “forward-looking statements". Forward-looking statements in this document include, but are
not limited to statements and tables with respect to: capital projects and expenditures; strategic initiatives; anticipated producer activity
and industry trends; and anticipated performance. Readers are cautioned not to place undue reliance on forward-looking statements, as
there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-
looking statements involve numerous assumptions, as well as known and unknown risks and uncertainties, both general and specific,
that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur and which
may cause Keyera’s actual performance and financial results in future periods to differ materially from any estimates or projections of
future performance or results expressed or implied by the forward-looking statements. These assumptions, risks and uncertainties
include, among other things: Keyera’s ability to successfully implement strategic initiatives and whether such initiatives yield the expected
benefits; future operating results; fluctuations in the supply and demand for natural gas, NGLs, crude oil and iso-octane; assumptions
regarding commodity prices; activities of producers, competitors and others; the weather; assumptions around construction schedules
and costs, including the availability and cost of materials and service providers; fluctuations in currency and interest rates; credit risks;
marketing margins; potential disruption or unexpected technical difficulties in developing new facilities or projects; unexpected cost
increases or technical difficulties in constructing or modifying processing facilities; Keyera’s ability to generate sufficient cash flow from
operations to meet its current and future obligations; its ability to access external sources of debt and equity capital; changes in laws or
regulations or the interpretations of such laws or regulations; political and economic conditions; and other risks and uncertainties
described from time to time in the reports and filings made with securities regulatory authorities by Keyera. Readers are cautioned that
the foregoing list of important factors is not exhaustive. The forward-looking statements contained in this document are made as of the
date of this document or the dates specifically referenced herein. For additional information please refer to Keyera’s public filings
available on SEDAR at www.sedar.com. All forward-looking statements contained in this document are expressly qualified by this
cautionary statement.
Disclaimer
2
Keyera
Strong track record & conservative financial strategy
Essential services to natural gas and oil sands producers
Strategically-located, integrated network of assets
Positioned for growth through financial flexibility
3
Conservative Financial Strategy
1 Compound annual growth rate from 5/30/2003 to 3/31/2017. 2 Compound annual growth rate from 7/15/2003 to 3/31/2017. 3 Based on dividends declared. Not a standard measure under GAAP. 4 From 4/1/2016 to 3/31/2017, inclusive.
12 %
cagr
d i s t r i b u t a b le ca sh
f l o w p e r sh a re 1 ,3
8 %
cagr
d i v i d e n d p e r sh a re 2 ,3
62 %
LT M p a yo u t r a t i o 3 ,4
4 Focused On Growing Shareholder Value
An Integrated Value Chain
Essential Midstream Infrastructure and Services 5
RAW
G AS
gathering
compression
sweetening
NGL extraction
EX
TR
AC
TIO
N
CO
NS
UM
PT
IO
N
GATHERING & PROCESSING
LIQUIDS BUSINESS UNIT
fractionation storage transportation marketing
ethane
propane
butane
condensate
iso-octane
F E E F O R S E R V I C E C O N T R A C T S M AR G I N
EN
D M
AR
KE
TS
1 Operating Margin shown excludes other income from production associated with Keyera’s oil and gas reserves. 2 See Keyera’s 2017 First Quarter Report MD&A and Note 13 to the accompanying financial statements.
Diversified and Growing Operating Margin
6 Fee-for-Service Business Underpins Balanced Growth
$0
$100
$200
$300
$400
$500
$600
$700
MillionsOPERATING MARGIN (ROLLING LTM)1,2
Gathering & Processing Liquids Infrastructure Marketing
AEF
Acquired
AEF
Turnaround
AEF
Turnaround
Investment Opportunities Continue
7 $800-$900 Million of Growth Capital Spending in 2017
1 Estimated growth capital for 2017 includes the pipeline acquisition cost of the South Grand Rapids project payable by Keyera upon completion of construction in 2H17. The acquisition capital in 2017 reflects
the $55 million purchase price for undeveloped land in the Industrial Heartland of Alberta completed in 1Q17.
$-
$200
$400
$600
$800
$1,000
12/31/12 12/31/13 12/31/14 12/31/15 12/31/16 12/31/17e
Millions ANNUAL CAPITAL EXPENDITURES
Growth Capital Upper End of Growth Capital Range Acquisitions Maintenance Capital
1
Select Completed Growth Projects
Growing in Response to Customer Demand 8
Completed Projects In-Service Date Capital Cost1
(Net, in $ Millions)
Fort Saskatchewan Fractionation Expansion May 2016 156
Zeta Creek New Gas Plant Construction September 2015 40
Rimbey Turbo Expander, Debottlenecking & Truck Offload Expansion July 2015 285
Josephburg Rail Terminal July 2015 120
Alder Flats New Gas Plant Construction (Phase I) May 2015 51
Twin Rivers Pipelines (Phases I & II) April 2015 67
Simonette Gas Plant Expansion (Condensate Stabilizer & Refrigeration Unit) March 2015 90
De-ethanizer at Keyera’s Fort Saskatchewan Fractionation Facility March 2015 165
Wapiti Raw Gas and Condensate Pipelines January 2015 180
$1,154 1 Some of the Completed Projects Capital Costs are subject to change, based on final adjustments.
Approved Projects Capital Cost (Net, in $ Millions)1
2017 2018 2019
Norlite Pipeline (JV with Enbridge) 390
Fort Saskatchewan Condensate System Pipeline Expansion & Manifold 28
Edmonton Terminal Condensate Tanks 50
South Grand Rapids Pipeline & Pump Station (JV with TCPL & Brion)2 145
NWR North Condensate Connector & South NGL Connector 50
Base Line Terminal Crude Oil Storage Project (JV with Kinder Morgan) 330
Hull Terminal Pipeline System Connection Project3 34
Alder Flats New Gas Plant Construction (Phase II)4 80
Keylink NGL Gathering Pipeline System 147
Simonette Liquids Handling Expansion Project 100
Wapiti Area Gathering & Processing Complex (Phase I) 470
Storage Cavern Development Program at Keyera Fort Saskatchewan 88
Other Projects (Connections, De-Bottlenecking, Land Development, etc.) >100
TOTAL >$2.0 Billion
Growth Projects Currently Under Development
Strong Capital Spending Profi le 9
1. Keyera’s share of estimated capital cost. See Keyera’s 2017 First Quarter MD&A for capital
investment risks and assumptions. 2. Pipeline portion of net capital cost will be paid upon
completion of construction and is categorized as acquisition capital. 3. Project cost is currently
estimated to be US$20-25 million. 4. $27 million was pre-paid in August 2016. The capital
budget and construction schedule for Phase II is being managed by Bellatrix Exploration Ltd.
Western Canada Sedimentary Basin
335 Billion boe u l t imate potent ia l recoverab le reserves
of c rude o i l and b i tumen 1
10
1 Alberta Energy Regulator’s “ST98-2017: Alberta’s Energy Reserves and Supply/Demand Outlook”, February 28, 2017
Globally Unique Multi-Zone Geology Underlies Alberta
Shale Carbonate Sandstone/Siltstone
/Mannville
/Ellerslie
/Fahler Spir
it R
iver
Keyera facilities
u l t imate potent ia l recoverab le reserves
o f na tura l gas 1
223 Tcf
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Gathering and Processing Business Unit
Well maintained, long-life facilities
– ~2.8 bcf/d licensed gross capacity1
– 17 active gas plants; 15 operated by Keyera
Extensive gathering systems
– Significant gathering pipelines tied into existing gas plants
– >4,000 kilometres of pipelines operated by Keyera
– Capture areas create franchise regions
Fee-for-service revenues with negligible direct commodity exposure
– Largely flow-through operating costs
Network of Facilities Supported by Fee-for-Service Contracts
1. Licensed capacity is not equivalent to actual operating capacity. Actual operational capacity can be lower as it depends on
operating conditions and capabilities of functional units at each plant.
11
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Core Infrastructure in West Central Alberta
Extensive, reliable and flexible network of assets
– 14 gas plants with ~2.1 Bcf/d gross licensed capacity1
– Expertise to handle sour gas and complete periodic maintenance turnarounds; critical mass to minimize flow-through operating costs
Recently expanded key facilities
– Rimbey turbo expander, fractionator debottlenecking and truck offload expansion
– Twin Rivers pipeline network optimization project
Additional gas plants constructed and acquired:
– Alder Flats (70% non-op owner)2 construction completed in 2015
– Zeta Creek (60% op owner)3 construction completed in 2015
– Cynthia gas plant (93% op owner) acquired in 2014
– Ricinus gas plant (71% op owner) acquired in 2014
Proposed Keylink NGL gathering pipeline system will connect eight gas plants to fractionation at Rimbey and Keyera Fort Saskatchewan
Integrated Network Provides Strength and Flexibility
1. Licensed capacity is not equivalent to actual operating capacity. Actual operating capacity can be lower as it depends on operating
conditions and capabilities of functional units at each plant. 2. Phase I of the Alder Flats gas plant came on stream in May 2015 and
provides 110 mmcf/d of licensed capacity. Phase II with an additional 120 mmcf/d of licensed capacity is expected to be completed in
1H18. In August 2016, Keyera acquired an additional 35% ownership interest in the Alder Flats gas plant and the associated gathering
system. 3. The Zeta Creek gas plant came on stream in September 2015 and provides 54 mmcf/d of licensed capacity.
12
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Spirit River – a Leading Low-Cost Natural Gas Play
Favourable geology
Broad, thick and extensive sand-rich valleys in
the Notikewin, Falher and Wilrich channels
Driver of activity is the Deep Basin nature of the
formation (no free water, sweet gas, liquids-rich)
Rivals the Montney, Utica and Marcellus
in well productivity and economics
Large majority of the top 20 gas wells
(calendar day rate) in Alberta in 20161
Keyera’s infrastructure well positioned to
handle continuing development
Keyera’s Assets Positioned Well to Support the Spirit River 13
1 Source: GeoScout, BMO Capital Markets
Spirit River – Brazeau/Ferrier Area
Map Source: Peters & Co., GeoScout
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Montney – Rich Geology Attracting Significant Capital
An Exciting Platform for Keyera’s Growth
1 Sources: Alberta Energy Regulator; BC Ministry of Natural Gas Development; BC Oil & Gas Commission;
National Energy Board; RBC Capital Markets, Scotiabank GBM.
Top-tier shale play in North America
Estimated to hold over 15 billion barrels of recoverable oil and NGLs1
– 100-300 metres thick in five or more exploitable layers in certain areas1
Significant land positions held by multinationals and others large producers
Attractive producer economics due to liquids-rich geology driving continuous infrastructure investment
Keyera’s Simonette gas plant and Wapiti area gathering and processing complex are well situated to capitalize on Montney development
14
Source: RBC Capital Markets,
EIA, AGS, Company Reports
Permian
SCOOP/STACK
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Simonette Liquids Handling Expansion Project
Significant Opportunities for Future Development
Enables Keyera to handle
growing volumes of condensate
and improve liquids recoveries
for customers
Facilities include above-ground
storage, truck loading,
redesigned existing condensate
stabilization and other new
services
Upon completion by mid-2018 for
an estimated cost of $100 million,
condensate handling capacity is
expected to be ~27,000 bbls/d1
15
1 Project cost and timing is subject to finalization of scope, cost estimates and construction schedule variables.
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Wapiti Area Gathering & Processing Complex
Increasing Keyera’s Presence in the Montney
1 Project cost and timing subject to project sanctioning, finalization of scope, timely receipt of remaining regulatory approvals and construction schedule variables. Currently expect Phase one to cost ~$470 million.
Montney sour gas gathering and processing complex:
Plant site and acid-gas injection well purchased in 2016
Primary producer sanctioned Phase one of the project in Q2 2017, which includes a long-term gas handling agreement including an area dedication and take-or-pay commitment
Facilities include:
Phase one: 150 mmcf/d of sour gas processing capacity; 25,000 bbls/d of condensate handling capacity; acid gas injection; raw gas gathering and field compression system
Proposed Phase two: additional 150 mmcf/d of sour gas processing capacity and extended gas gathering system
Phase one target in-service date of mid-20191
Estimated cost of both phases ~$625 million1
16
Producers active in the
Wapiti area: • Apache
• CNRL
• Conoco
• Encana
• NuVista
• Paramount
• Seven Generations
• Shell
• Sinopec-Daylight
Future potential to connect the plant to Keyera’s Wapiti pipeline and Simonette gas plant
Duvernay – The Next Frontier
17 Existing Gas Plants Well Positioned for Future Development
Figure 1 from the AER’s
“Duvernay Reserves and Resources Report”
published December 2016.
395 mi l l ion boe remain ing reserves
of o i l , natural gas and condensate 1
1 Total Proved + Probable Duvernay Reserves published by the AER in December 2016.
2 Excerpts from Sections 1.2 and 7.2, respectively, of the “Duvernay Reserves and Resources Report”, December 2016.
3 Excerpt from the Executive Summary of the AER “Duvernay Reserves and Resources Report”, December 2016.
Significant reserves for the long-term:
– Emerging as one of Alberta’s foremost unconventional condensate-rich shale resources
– Covers ~130,000 square kilometres or 20% of Alberta; >3,200 wells could be drilled over next 15 years2
Existing Keyera gathering and processing assets ready to serve the Duvernay:
– Simonette gas plant is located in the northern Fox Creek area
– Vast gas plant and pipeline infrastructure network in the southern (Edson-Willesden Green) area
HIST ORICAL T HROUGHPUT & T HE PERCENT AGE CHANGE IN AECO & WT I T O M ARCH 2017
Relatively Stable Throughput
18 Volumes Relatively Steady as Commodity Prices Fluctuate
-100%
-50%
0%
50%
100%
150%
200%
250%
300%
-
200
400
600
800
1,000
1,200
1,400
1,600
Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17
% Change in Commodity Price since January 2003
Gross Plant Throughput(MMcf/d)
Rimbey Strachan Edson
Alder Flats West Pembina Simonette
Nordegg Cynthia Nevis
Minnehik Buck Lake Brazeau North & Pembina North Brazeau River
Zeta Creek Ricinus Gilby
Bigoray AECO Monthly Natural Gas Price (CA$) WTI Monthly Oil Price (US$)
Liquids Business Unit
e t h a n e
p r o p a n e
c o n d e n s a t e
BU T AN E
ABOVE GROUND
BELOW GROUND
~2300
AEF ISO-OCTANE (13,600 bbls/d)
FRACTIONATION STORAGE SPEC PRODUCT
TRANSPORTATION MARKETING
Unmatched Infrastructure for NGL and Oil Sands Customers
~13 mi l l ion bbls of gross cavern capaci ty
~90,000 bbls /d of net f ract ionat ion capaci ty at f ive locat ions
Rai l and truck terminals and pipel ines t ransport ing var iety of NGLs
19
>520,000 bbls of gross working tank capaci ty
NG
L M
IX T
RA
NS
PO
RT
AT
ION
An Integrated NGL Transportation Solution
Keylink NGL Gathering Pipeline System
20
New NGL gathering solution for liquids egress and network integration:
1 Capacity, length, cost and timing subject to finalization of scope, timely receipt of third party consent and remaining regulatory approvals and construction schedule variables.
– NGL gathering pipeline system strengthens
Keyera’s value chain by connecting eight
Keyera gas plants to the Rimbey energy
complex
– NGLs can be fractionated at Rimbey or at
Keyera Fort Saskatchewan (via Rimbey
Pipeline and the FSPL system)
– Capacity of ~22,000 bbls/d1
– Combination of new and re-purposed existing
pipelines with a total system length of 264 km1
– Estimated cost of $147 million, with an
expected in-service date of mid-20181
Fractionation at Multiple Locations
21 Adding Value by Processing NGLs from the Gas Stream
Keyera Fort Saskatchewan
Gilby Gas Plant
3,650 bbls/d gross (2,930 bbls/d net) of C3+ fractionation capacity
Nevis Gas Plant
3,740 bbls/d of C3+ fractionation capacity
Rimbey Gas Plant
28,000 bbls/d gross (27,640 bbls/d net) of C3+ fractionation capacity
20,000 bbls/d gross (19,740 bbls/d net) of ethane extraction capacity
65,200 bbls/d gross (50,000 bbls/d net) of
C3+ fractionation capacity
30,000 bbls/d gross (23,010 bbls/d net) of
de-ethanization capacity
Dow Fort Saskatchewan
30,000 bbls/d gross (5,420 bbls/d net) of C3+ fractionation capacity
69,200 bbls/d gross (6,920 bbls/d net) of de-ethanization capacity
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Expanding Underground Storage at KFS
Continued Growth at the Fort Saskatchewan Energy Complex
Underground storage capacity expansion project:
– 14th cavern in-service in 2Q17
– 15th cavern currently being washed; expected in-service in 1H181
– Drilled well bores for 16th and 17th caverns in 3Q16; washing of the 16th cavern commenced in 1Q17
Net cost to complete the four-cavern underground storage development program is approximately $88 million
22
1 Timing subject to receipt of remaining regulatory approvals and completion of washing at the expected pace.
Bitumen Production Growth Driving Condensate Demand
Oil Sands Production Continues to Grow
23
Company
Select Projects
Sanctioned and/or
Under Construction
Capacity
(MB/d) Timing
PetroChina
(Brion) MacKay Phase 1 35 2017
CNRL Horizon Phase 3 80 2018
JACOS /
CNOOC
Hangingstone
Expansion 20
2017-
2018
CNRL Horizon
Debottlenecks 10
2017-
2018
MEG Phase 2B Brownfield
/eMSAGP 30
2017-
2020
Suncor /
Total /
Teck
Fort Hills 194 2017
KNOC BlackGold Phase 1 10 2018
Cenovus Christina Lake
Phase G 50 2019
CNRL Kirby North 40 2020
Total Capacity Being Added 469
WCSB Condensate Market: Supply vs Demand Oil Sands Production: Mining vs In Situ
Extensive, Flexible Condensate Infrastructure
Most connected condensate hub in Western Canada
Major oil sands delivery options:
Supply through multiple receipt points:
– Local fractionators and refineries
– Kinder Morgan Cochin pipeline
– Enbridge Southern Lights pipeline and CRW pool
– Western Canada feeder pipelines
– Rail imports at the Alberta Diluent Terminal
Storage at Keyera Fort Saskatchewan
Long-term take-or-pay and fee-for-service agreements:
– Imperial Oil (Kearl)
– Husky/BP (Sunrise)
– Suncor/Teck/Total (Fort Hills)
– North West Upgrading
– Cenovus (Christina Lake)
– CNRL (Kirby, Primrose)
– JACOS/Nexen (Hangingstone)
– Devon (Jackfish)
Industry-Leading Diluent Handling Services 24
– Polaris
– Norlite
– Access
– FSPL
– Grand Rapids
– South Cheecham
Keyera’s Condensate Network
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Diluent pipeline from Ft. Saskatchewan to Athabasca oil sands
Enbridge is constructing and will operate Norlite once in service
Keyera is a 30% owner
Line-fill activities started in mid May; pipeline will be operational shortly thereafter
Long-term take-or-pay agreement with owners of Fort Hills project – Suncor, Total and Teck
Norlite shippers can contract for services through Keyera’s other condensate infrastructure in Edmonton/Fort Saskatchewan, including storage and rail
Initial capacity of approximately 218,000 bbls/d with potential to expand to 465,000 bbls/d1 at gross cost of $1.3 billion ($390 million net to Keyera)2
Will Provide Additional Long-Term Stable Cash Flows
Norlite Pipeline
1 Pipeline capacities are estimated based on certain assumptions. 2 Final cost subject to change.
25
50/50 joint venture between Keyera and Grand Rapids Pipeline LP (TransCanada PipeLines and Brion Energy)
45-kilometre 20-inch diluent pipeline from Edmonton to Fort Saskatchewan
Will provide Keyera with ≥225,000 bbls/d of net capacity1 for diluent transportation, a portion of which will be used to meet commitments under existing customer agreements
Remaining capacity available for Keyera to pursue new diluent transportation business
Net capital cost to Keyera expected to be $145 million2
Expected in service late 20173
Keyera will operate the pipeline once complete
Further Enhancing and Expanding our Condensate Network
South Grand Rapids Pipeline
1 Pipeline capacities are estimated based on certain assumptions.
2 Pipeline portion of net capital cost will be paid upon completion of construction and is categorized as acquisition capital.
3 Cost and timing subject to construction and schedule variables.
26
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50/50 joint venture operated by Kinder Morgan
12 crude oil storage tanks with 4.8 million bbls of capacity under construction at Keyera’s Alberta EnviroFuels site
Connected to Kinder Morgan’s Edmonton terminal
Backstopped by 8 customers with take-or-pay contracts up to 10 years in length
Expected net capital cost to Keyera of $330 million1
Potential to add additional tanks for total storage capacity of up to 6.6 million bbls, subject to customer demand
Phased commissioning of tanks starting in 1Q181
Expanding and Diversifying Keyera’s Service Offering
1 Cost and timing subject to construction and schedule variables.
Tank Legend:
Proposed = White
Future = Brown
Base Line Terminal
Concept Rendering (View Looking North)
Base Line Terminal – a Crude Oil Storage Solution
27
Multi-Purpose Terminals Across Alberta
Transporting Commodities Between Regional Markets 28
Keyera Josephburg Terminal
22,400 bbls/d rail capacity1,2
Alberta Crude Terminal
40,000 bbls/d gross rail capacity (20,000 bbls/d net)1
Alberta Diluent Terminal
50,000 bbls/d rail capacity1 & 342,600 bbls storage capacity
South Cheecham Rail & Truck Terminal
24,000 bbls/d gross rail loading capacity (12,000 bbls/d net)1 15,000 bbls/d gross rail offloading capacity (7,500 bbls/d net)1
51,000 bbls storage capacity (25,500 bbls net)
Keyera Edmonton Terminal
34,000 bbls/d rail capacity1 240,000 bbls of storage capacity (under construction)
1 Rail capacity is an estimated calculation taking into account such factors as the number of railcar spots at each facility, the frequency of switches provided by the railways at each facility and the type of product being loaded or off-loaded.
2 The capacity identified for the Josephburg Rail Terminal is based on the facility operating 12 hours per day, should the hours of operation increase, the capacity would also increase.
Undeveloped Land for Future Growth
29 Strategic Optionality in the Industrial Heartland of Alberta
Close
proximity
to pipelines
and railroads
Keyera holds
salt rights
beneath
most of
these lands
166 undeveloped acres 1290 undeveloped acres 132 undeveloped acres
Keyera Josephburg Terminal (KJT) Keyera Fort Saskatchewan (KFS)
350 undeveloped acres
Keyera’s Hull Terminal in Texas
Rail, truck and pipeline terminal handles
NGL mix, propane, butane and iso-butane
Acquired a 88-kilometre, 6-inch pipeline
system for US$24 million in 2016
Reactivating and connecting the pipeline
system for an estimated cost (incl. third
party connection) of US$20-25 million1
Proposed third-party pipeline connection
will provide access to Mont Belvieu:
- Agreement with a major US midstream company to
build the connection signed in 4Q16
- Commercial terms secure storage and other
midstream services in Mont Belvieu post-
construction
Hull Terminal and Pipeline System
Enhancing Keyera’s Access to Mont Belvieu 30
1 Cost and timing subject to finalization of scope for pipeline connections and other improvements, construction and schedule variables.
Proposed system flow by mid-2018
Diversified Portfolio of Logistics Services
Marketing Services
C3 Propane
• Supply exceeds demand in North America
• Majority sold into U.S. markets
• Producers bear a significant majority of the
commodity price risk
• Demand varies seasonally
C2 Ethane
• Sold under long-term agreements to
petrochemical producers in Alberta
• Limited spot market in western Canada
• Produced at three Keyera facilities
C4 Butane
• Sourced and consumed in Alberta
• Feedstock for iso-octane production at
Alberta EnviroFuels
• Seasonal imports from the U.S.
iC8 Iso-octane
• Majority of sales in the U.S.
• High quality gasoline additive
• Produced from butane at Keyera’s
Alberta EnviroFuels plant
C5 Condensate
• Keyera’s C5 hub creates industry liquidity
• Consumed in Alberta as diluent for bitumen
• Demand from the oil sands greatly exceeds
Alberta-based supply
• Significant imports required today
31
Alberta EnviroFuels (AEF)
iC8 is Premium Value-Added Product Produced in Alberta
Iso-octane (iC8) is a high octane, low vapour
pressure gasoline additive
Butane is the NGL feedstock
Only merchant iC8 facility in North America
Licensed capacity of 13,600 bbls/d
Supply networks and distribution infrastructure
used to source feedstock while rail logistics
broaden sales markets
Financial forward markets enable hedging of
feedstock costs and large portion of iC8 sales
iC8 demand driven by premium gasoline demand
Seasonality is complementary to propane and
butane
32
Iso-Octane Business and its Margin Components
Iso-Octane is a High-Value, Low-Volume Business 33
NOTE: Components are not indicative of their relative size in the margin equation.
Cost
Components
Revenue
Components
Risk Management
Foreign Exchange
(iC8 sold in USD)
Iso-Octane (iC8)
Premium over RBOB
RBOB Premium over WTI
WTI
Strong demand for iso-octane
- 13,600 bbls/d of facility capacity
- Annual peak occurs during summer driving season
Access to butane feedstock
- Sourced locally and from the US
- Utilize cavern storage assets and pipeline network to
manage volumes and costs
Operational expertise to maximize utilization
Access to continental markets
- Leverage Keyera’s rail terminals, storage facilities
and logistical expertise to identify best opportunities
- Sell into regions with the strongest demand across
North America, including the US Gulf Coast and
Midwest to maximize iso-octane premiums
Risk Management
Periodic Plant Maintenance
Plant Operating Expenses,
Storage & Transportation Costs
~1.4 bbl of C4 per bbl of iC8
Butane (C4) as a Fraction
of WTI (priced in USD)
1 Calculated as of March 31, 2017 in accordance with Keyera’s debt covenants. For further information regarding covenant calculations, please see Keyera’s
2017 First Quarter Report MD&A or copies of the note purchase agreements, all of which are filed on SEDAR. 2 Enterprise value based on total shares
outstanding as at May 1, 2017 and a closing share price of $39.63 (TSX:KEY). 3 All US dollar denominated debt is translated into Canadian dollars at its swap
rate. 4 Midstream Peer Group includes ALA, ENB, GEI, IPL, PPL, TRP and VSN.
LONG -T ERM DEBT MAT URIT IES 3 ( exc ludes d rawings under r evo lve r )
2.6x
Net Debt1 to Adj. EBITDA vs Midstream Peer Group4 Average >5.0x
18% Net Debt1 to Enterprise Value2 vs Midstream Peer Group4 Average >35%
Conservative Capital Structure
34 Flexibility to Fund Keyera’s Capital Program
$60
$0
$125
$109
$0
$60$30
$143
$264
$230
$0
$267
$75
$0
$50
$100
$150
$200
$250
$300
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
$CAD MM
Current Financial Results
35
1Q17 1Q16 Change 2016 2015 Change
Operating Margin
Gathering & Processing 66 68 -3% 290 259 12%
Liquids Infrastructure 65 62 5% 246 220 12%
Marketing 68 44 55% 101* 244** -59%
Other 5 2 150% 9 20 -55%
Total Operating Margin1 204 176 16% 646 742 -13%
Adjusted EBITDA2 148 145 2% 605 705** -14%
Net Earnings 96 70 37% 217 202 7%
Distributable Cash Flow3 121 116 4% 460 482** -5%
Per Share 0.65 0.68 -4% 2.56 2.84 -10%
Payout Ratio4 61% 56% 9% 60% 50% 20%
*Reflects the scheduled turnaround at AEF in 2H16. **Reflects approximately $40 million non-recurring cash gain related to the settlement of risk management contracts associated with 2014 year-end inventory.
1 Total Operating Margin refers to total operating revenues less total operating expenses and general and administrative expenses associated with the Marketing segment. See Note 13 to the accompanying
financial statements. 2 Adjusted EBITDA is not a standard measure under GAAP. See Keyera’s 2017 First Quarter Report MD&A for a definition of EBITDA and Adjusted EBITDA and for a reconciliation of
Adjusted EBITDA to its related GAAP measure. 3 Distributable cash flow is not a standard measure under GAAP. See Keyera’s 2017 First Quarter Report MD&A for a definition of Distributable Cash Flow and for a
reconciliation of Distributable Cash Flow to its related GAAP measure. 4 Payout ratio is not a standard measure under GAAP. Payout ratio is defined as dividends declared to shareholders divided by distributable
cash flow.
(Millions of Canadian dollars, except where noted)
Strong Performance Over the Last Two Years
Investment Summary
1 Total return includes the simple receipt of dividends paid by Keyera and the TSX between May 30, 2003 and March 31, 2017, but not the reinvestment of dividends in any assumed security. 2 Distributable
cash flow is not a standard measure under GAAP. See Keyera’s 2017 First Quarter Report MD&A for a definition of distributable cash flow and for a reconciliation of distributable cash flow to its related GAAP
measure. 3 Payout ratio is not a standard measure under GAAP. Payout ratio is defined as dividends declared to shareholders divided by distributable cash flow.
36 Providing Growth and Income for Shareholders
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
$-
$0.25
$0.50
$0.75
$1.00
$1.25
$1.50
$1.75
$2.00
$2.25
$2.50
$2.75
$3.00
Payout Ratio
Per Share (split-adj.)
DISTRIBUTABLE CASH FLOW, PAYOUT RATIO & DIVIDENDS PER SHARE
Distributable Cashflow per Share Payout Ratio Dividends per Share2 3
$100
$300
$500
$700
$900
$1,100
TOTAL RETURN OF A $100 INVESTMENT IN KEYERA and THE S&P/TSX COMPOSITE INDEX
TSX Total Return Keyera Total Return
1
A Well Positioned Midstream Company
37 Operational and Financial Flexibi l i ty
diversified
customer base
& service
offering
strong
balance sheet
& low payout
ratio
Alberta
EnviroFuels
iso-octane
business
industry
leading
condensate
system
NGL
fractionation
& cavern
storage
capacity
networked
gas plants
& gathering
systems
Lavonne Zdunich, CA
Director, Investor Relations & Communications
Nick Kuzyk, MBA
Manager, Investor Relations
888-699-4853
Contact Information
Keyera Corp. 144 4 Avenue SW
Suite #200 - West Tower
Calgary, Alberta
T2P 3N4
www.keyera.com
38
